Production of hydrocarbon using direct-contact steam generation

ABSTRACT

A process for in situ thermal recovery of hydrocarbons from a reservoir is provided. The process includes: providing an oxygen-enriched mixture, fuel, feedwater and an additive including at least one of ammonia, urea and a volatile amine to a Direct-Contact Steam Generator (DCSG); operating the DCSG, including contacting the feedwater and the additive with hot combustion gas to obtain a steam-based mixture including steam, CO 2  and the additive; injecting the steam-based mixture or a stream derived from the steam-based mixture into the reservoir to mobilize the hydrocarbons therein; and producing a produced fluid including the hydrocarbons.

CROSS-RELATED APPLICATION

The present patent application claims priority on Canadian patentapplication No. 2,943,314, which is hereby incorporated by reference inits entirety.

TECHNICAL FIELD

The technical field generally relates to in situ hydrocarbon recoveryoperations, and more particularly to steam-assisted hydrocarbon recoveryoperations.

BACKGROUND

Steam-assisted hydrocarbon recovery techniques are widely used torecover hydrocarbons such as heavy oil and/or bitumen from subsurfacereservoirs. Steam-assisted gravity drainage (SAGD) is one of suchtechniques. Typically, in a SAGD hydrocarbon recovery operation, a pairof horizontal wells is drilled into a hydrocarbon-bearing reservoir,such as an oil sands reservoir, and steam is continuously injected intothe reservoir via the upper injection well to heat and reduce theviscosity of the hydrocarbons. The mobilized hydrocarbons drain into thelower production well and are recovered to surface.

In SAGD operations or other in situ hydrocarbon recovery operations, itmay be desirable under certain circumstances to co-inject additives,such as ammonia, along with the steam. However, with existingtechniques, the handling of such additives and their integration withinthe steam stream can have certain drawbacks, such as high cost. Forexample, some scenarios using chemical skids in order to co-inject theadditives can lead to increased safety risks and increased surfacefootprint (i.e., increased maintenance and supervision). Chemical skidscan also require production shut-in for tie-in, and can add complexitybecause of the handling of chemicals (e.g., safety) and more demandinglogistics (e.g., loading, chemical inventory).

Various challenges still exist in the area of in situ hydrocarbonrecovery and steam generation.

SUMMARY

In some implementations, a process for in situ thermal recovery ofhydrocarbons from a reservoir is provided. The process comprises:providing an oxygen-enriched mixture, fuel, feedwater and an additivecomprising at least one of ammonia, urea and a volatile amine to adirect-contact steam generator (DCSG); operating the DCSG, comprisingcontacting the feedwater and the additive with hot combustion gas toobtain a steam-based mixture comprising steam, CO₂ and the additive;injecting the steam-based mixture or a stream derived from thesteam-based mixture into the reservoir to mobilize the hydrocarbonstherein; and producing a produced fluid comprising the hydrocarbons.

In some implementations, the additive comprises ammonia.

In some implementations, the ammonia is provided as an ammoniumhydroxide solution.

In some implementations, the concentration of ammonia and/or volatileamine in the steam-based mixture is between about 0.1 wt % and about 30wt %.

In some implementations, the steam-based mixture comprises the additivein a gaseous and/or vapor state.

In some implementations, the additive further comprises at least one ofa viscosity reduction agent and a well integrity agent.

In some implementations, the well integrity agent is chosen from thegroup consisting of an anticorrosive agent, an antifouling agent, ascale inhibitor and thermally stable cement.

In some implementations, the process further includes providing a wastestream comprising volatile organic components (VOCs) to the DCSG, inorder to flare the VOCs in the DCSG.

In some implementations, the feedwater and the additive are provided asa single feed stream to the DCSG.

In some implementations, the feedwater is provided as a feedwater streamand the additive is provided as a separate additive stream, to the DCSG.

In some implementations, the feedwater stream is contacted with the hotcombustion gas for a longer time period than the additive stream.

In some implementations, the process further includes separating atleast part of the CO₂ from the steam-based mixture, to obtain a CO₂-leansteam-based mixture as the stream derived from the steam-based mixture.

In some implementations, the process further includes separating theproduced fluid into produced gas, a non-gaseous hydrocarbon componentand produced water.

In some implementations, the feedwater comprises at least part of theproduced water.

In some implementations, the feedwater further comprises makeup water.

In some implementations, the concentration of the makeup water in thefeedwater is of up to about 5 wt % of the feedwater.

In some implementations, the fuel comprises at least part of theproduced gas.

In some implementations, a process for SAGD recovery of hydrocarbonsfrom a reservoir is provided. The process includes: providing anoxygen-enriched mixture, fuel, feedwater and an additive to a DCSG, theadditive comprising at least one of ammonia, urea and a volatile amine;operating the DCSG, comprising contacting the feedwater and the additivewith hot combustion gas to obtain a steam-based mixture comprisingsteam, CO₂ and the additive; injecting the steam-based mixture or astream derived from the steam-based mixture into the reservoir via aSAGD injection well to mobilize hydrocarbons therein; and recovering thehydrocarbons as produced fluids from a SAGD production well.

In some implementations, the additive comprises ammonia.

In some implementations, the ammonia is provided as an ammoniumhydroxide solution.

In some implementations, the concentration of the ammonia and/orvolatile amine in the steam-based mixture is between about 0.1 wt % andabout 30 wt %.

In some implementations, the steam-based mixture comprises the additivein a gaseous state.

In some implementations, the additive further comprises at least one ofa viscosity reduction agent and a well integrity agent.

In some implementations, the well integrity agent is chosen from thegroup consisting of an anticorrosive agent, an antifouling agent, ascale inhibitor and thermally stable cement.

In some implementations, the process further includes providing a wastestream comprising volatile organic components (VOCs) to the DCSG, inorder to flare the VOCs in the DCSG.

In some implementations, the feedwater and the additive are provided asa single feed stream to the DCSG.

In some implementations, the feedwater is provided as a feedwater streamand the additive is provided as a separate additive stream, to the DCSG.

In some implementations, the feedwater stream is contacted with the hotcombustion gas for a longer time period than the additive stream.

In some implementations, the process further includes separating atleast part of the CO₂ from the steam-based mixture, to obtain a CO₂-leansteam-based mixture as the stream derived from the steam-based mixture.

In some implementations, the process further includes separating theproduced fluid into produced gas, a non-gaseous hydrocarbon componentand produced water.

In some implementations, the feedwater comprises at least part of theproduced water.

In some implementations, the feedwater further comprises makeup water.

In some implementations, the concentration of the makeup water in thefeedwater is of up to about 5 wt % of the feedwater.

In some implementations, the fuel comprises at least part of theproduced gas.

In some implementations, a process for generating a steam-based mixtureis provided. the process includes: providing an oxygen-enriched mixture,fuel, feedwater and an additive comprising at least one of ammonia, ureaand a volatile amine, to a DCSG; and operating the DCSG, comprisingcontacting the feedwater and the additive with hot combustion gas toobtain the steam-based mixture comprising steam, CO₂ and the additive.

In some implementations, the additive comprises ammonia.

In some implementations, the ammonia is provided as an ammoniumhydroxide solution.

In some implementations, the concentration of the ammonia and/orvolatile amine in the steam-based mixture is between about 0.1 wt % andabout 30 wt %.

In some implementations, the steam-based mixture comprises the additivein a gaseous state.

In some implementations, the feedwater and the additive are provided asa single feed stream to the DCSG.

In some implementations, the feedwater is provided as a feedwater streamand the additive is provided as a separate additive stream, to the DCSG.

In some implementations, the feedwater stream is contacted with the hotcombustion gas for a longer time period than the additive stream.

In some implementations, the process further includes separating atleast part of the CO₂ from the steam-based mixture, to obtain a CO₂-leansteam-based mixture.

In some implementations, the feedwater comprises at least part of aproduced water component from an in situ hydrocarbon recovery operation.

In some implementations, the feedwater further comprises makeup water.

The process of claim 45, wherein the concentration of the makeup waterin the feedwater is of up to about 5 wt % of the feedwater.

In some implementations, the fuel comprises at least part of a producedgas component from an in situ hydrocarbon recovery operation.

In some implementations, a system for recovering hydrocarbons from areservoir is provided. The system includes: a DCSG for generating asteam-based mixture, the DCSG comprising: an oxygen inlet for receivingan oxygen-enriched mixture; a fuel inlet for receiving fuel; and atleast one inlet for receiving feedwater and an additive comprising atleast one of ammonia, urea and a volatile amine, the steam-based mixturecomprising steam, CO₂ and the additive; an injection well in fluidcommunication with the DCSG to receive the steam-based mixture or astream derived from the steam-based mixture; a production well forrecovering produced fluids from the reservoir; and a hydrocarbonseparating unit in fluid communication with the production well toreceive the produced fluids and separate the hydrocarbons from theproduced fluids.

In some implementations, the additive comprises ammonia.

In some implementations, the ammonia is provided as an ammoniumhydroxide solution.

In some implementations, the steam-based mixture comprises the additivein a gaseous state.

In some implementations, the additive further comprises at least one ofa viscosity reduction agent and a well integrity agent.

In some implementations, the concentration of the ammonia and/orvolatile amine in the steam-based mixture is between about 0.1 wt % andabout 30 wt %.

In some implementations, the well integrity agent is chosen from thegroup consisting of an anticorrosive agent, an antifouling agent, ascale inhibitor and thermally stable cement.

In some implementations, the DCSG further comprises a waste inlet forreceiving a waste stream comprising volatile organic components (VOCs)to the DCSG, in order to flare the VOCs by contact with the hotcombustion gas.

In some implementations, the at least one inlet for receiving thefeedwater and the additive is a single inlet, such that the feedwaterand the additive are provided as a single feed stream to the DCSG.

In some implementations, the at least one inlet for receiving thefeedwater and the additive comprises a feedwater inlet and a separateadditive inlet, such that the feedwater is provided as a feedwaterstream and the additive is provided as a separate additive stream, tothe DCSG.

In some implementations, the feedwater inlet and the additive inlet arepositioned such that the feedwater stream is contacted with hotcombustion gas for a longer time period than the additive stream.

In some implementations, the system further includes a steam-CO₂separator downstream of the DCSG for separating at least part of the CO₂from the steam-based mixture and obtain a CO₂-lean steam-based mixture.

In some implementations, the hydrocarbon separating unit separates theproduced fluids into produced gas, a non-gaseous hydrocarbon componentand produced water.

In some implementations, the system further includes a water recycleline for providing at least part of the produced water as at least partof the feedwater of the DCSG.

In some implementations, the system further includes a makeup water linefor supplying makeup water to the DCSG from a water source.

In some implementations, the concentration of the makeup water in thefeedwater is between of up to about 5 wt % of the feedwater.

In some implementations, the system further includes a gas recycle linefor providing at least part of the produced gas as at least part of thefuel of the DCSG.

In some implementations, a method for recovering hydrocarbons in ahydrocarbon recovery operation, the hydrocarbon recovery operationcomprising an injection well and a production well overlying a reservoirfrom a well pad. the method includes: proximate to the well pad:recovering produced fluids from the production well; separating theproduced fluids into produced water and produced hydrocarbons; operatinga DCSG, comprising: providing an oxygen-enriched mixture, fuel andfeedwater comprising at least a portion of the produced water, to theDCSG; providing an additive in a liquid state to the DCSG or to anoutlet stream of the DCSG; generating a steam-based mixture comprisingsteam, CO₂ and the additive in a gaseous state and/or a dispersed state;injecting the steam-based mixture or a stream derived from thesteam-based mixture into the injection well; and supplying the producedhydrocarbons to a distant processing facility.

In some implementations, the additive is provided to the DCSG from alocation proximate to the well pad.

In some implementations, the produced hydrocarbons comprise a producedgas component and a non-gaseous hydrocarbon component.

In some implementations, at least a portion of the produced gas is usedas at least a portion of the fuel for the DCSG.

In some implementations, the additive is mixed with the feedwater priorto being provided to the DCSG.

In some implementations, the additive and the feedwater are provided tothe DCSG as separate feed streams.

In some implementations, the additive comprises at least one of ammoniaand a volatile amine.

In some implementations, the ammonia is provided as an ammoniumhydroxide solution.

In some implementations, the additive includes at least one of aviscosity reduction agent and a well integrity agent.

In some implementations, the well integrity agent is chosen from thegroup consisting of an anticorrosive agent, an antifouling agent, ascale inhibitor and thermally stable cement.

In some implementations, a process for in situ thermal recovery ofhydrocarbons from a reservoir is provided. The process includes:providing an oxygen-enriched mixture, fuel, feedwater and an additive inliquid state to a DCSG; operating the DCSG, including contacting thefeedwater and the additive with hot combustion gas to obtain asteam-based mixture including steam, CO₂ and the additive in a gaseousstate and/or a dispersed state; injecting the steam-based mixture or astream derived from the steam-based mixture into the reservoir tomobilize the hydrocarbons therein; and producing a produced fluidincluding the hydrocarbons.

In some implementations, the additive includes at least one of ammoniaand a volatile amine.

In some implementations, the ammonia is provided as an ammoniumhydroxide solution.

In some implementations, the additive further includes at least one of aviscosity reduction agent and a well integrity agent.

In some implementations, the well integrity agent is chosen from thegroup consisting of an anticorrosive agent, an antifouling agent, ascale inhibitor and thermally stable cement.

In some implementations, the process further includes providing a wastestream including volatile organic components (VOCs) to the DCSG, inorder to flare the VOCs in the DCSG.

In some implementations, the feedwater and the additive are provided asa single feed stream to the DCSG.

In some implementations, the feedwater is provided as a feedwater streamand the additive is provided as a separate additive stream, to the DCSG.

In some implementations, a process for in situ thermal recovery ofhydrocarbons from a reservoir is provided. The process includes:providing an oxygen-enriched mixture, fuel, feedwater and an additive into a DCSG, the additive being carried by a heat carrier gas; operatingthe DCSG, including contacting the feedwater and the additive with hotcombustion gas to obtain a steam-based mixture including steam, CO₂ andthe additive, the heat carrier gas providing stability to the additiveduring operation of the DCSG; injecting the steam-based mixture or astream derived from the steam-based mixture into the reservoir tomobilize the hydrocarbons therein; and producing a produced fluidincluding the hydrocarbons.

In some implementations, the additive further includes at least one of aviscosity reduction agent and a well integrity agent.

In some implementations, the well integrity agent is chosen from thegroup consisting of an anticorrosive agent, an antifouling agent, ascale inhibitor and thermally stable cement

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a process flow diagram of a hydrocarbon recovery operation,showing possible additive injection points;

FIG. 2A is a process flow diagram of a hydrocarbon recovery operation,showing possible additive injection points and featuring a steam/CO₂separation step;

FIG. 2B is a process flow diagram of a hydrocarbon recovery operation,showing possible additive injection points and featuring a steam/CO₂membrane separation step; and

FIG. 3 is a top schematic view of a hydrocarbon recovery system withsteam generation, water recycling and additive delivery at remotehydrocarbon recovery facilities.

DETAILED DESCRIPTION

Various techniques that are described herein enable thermal in siturecovery operations of hydrocarbons, such as steam-assisted gravitydrainage (SAGD), including the use of a direct-contact steam generator(DCSG) for generating steam. The outlet stream generated by the DCSGtypically includes steam and CO₂ and may be referred to as a combustionmixture or a steam-based mixture. While the combustion mixture can bedirectly injected into a reservoir to mobilize the hydrocarbons therein,in some scenarios it can be desirable to co-inject an additive into thereservoir along with the combustion mixture. In some scenarios,co-injection of an additive can improve bitumen recovery, can provide acertain benefit to existing tubing or downhole tools including electricsubmersible pumps (ESPs), enhance conformance, or provide solutions toformation damage. The additive can be mixed with the combustion mixturedownstream of the DCSG, or can alternatively be injected into the DCSGalong with feedwater so that the additive is incorporated into thesteam-based mixture as the steam-based mixture is generated.

A DCSG generates steam by directly contacting feedwater with a hotcombustion gas which is produced using fuel (for example, natural gas)and an oxidizing gas (for example, an oxygen-enriched gas mixture, suchas purified oxygen). Depending on the oxidizing gas and fuel that areused, the combustion gas can include various amounts of carbon dioxide(CO₂) as well as other gases such as carbon monoxide (CO), hydrogen(H₂), nitrogen based compounds (NO_(x)) such as nitric oxide (NO) andnitrogen dioxide (NO₂), and/or sulfur based compounds (SO_(x)) such assulfur oxides. The fuel and oxidizing gas can be premixed prior toreaching a burner, and a flame is generated in a combustion chamber,thereby forming the hot combustion gas. The feedwater is typically rundown the combustion chamber in jacketed pipes and into an evaporationchamber, and the hot combustion gas evaporates the feedwater in theevaporation chamber, thereby generating the outlet stream which includessteam and combustion gas, which typically mostly includes CO₂.

There are several types of additives that can be incorporated into thesteam-based mixture, depending for example on the nature of thereservoir, production stage (start-up, ramp up, plateau, decline, winddown), the configuration of the hydrocarbon recovery operation, economicand/or environmental parameters. In some implementations, the additivecan be a liquid additive which is vaporizable and/or dispersible intothe combustion mixture, such as ammonia or a volatile amine, or anyother additive desired. In some scenarios, injecting the additive intothe DCSG for vaporizing and/or dispersing into the combustion mixturecan reduce costs and/or increase safety compared to having to vaporizethe additive prior to injecting the additive into the combustionmixture.

DCSGs can be located at remote hydrocarbon recovery facilities due totheir small size and scalability, and steam can thereby be generatedproximate to the well pads as opposed to being generated at a distantprocessing facility and conveyed to the well pad. The CO₂ included inthe combustion gas can either be co-injected with the steam into theinjection well (in whole or in part), or separated prior to theinjection. In some scenarios, the additives to be co-injected can bestored proximate to the well pads, at each remote hydrocarbon recoveryfacility, or dissolved in the feedwater thereby potentially reducing thecosts and/or safety considerations. In some scenarios, using DCSGs atremote hydrocarbon recovery facilities can allow for eliminatingchemical skids.

Some implementations of the technology are described in greater detailbelow.

Steam Generation Implementations

Referring to FIG. 1, a hydrocarbon recovery operation usingsteam-assisted gravity drainage is shown. It should be understood thatthroughout the present description, hydrocarbon recovery using SAGD isused to illustrate the various implementations. It should be understoodthat the processes and techniques of the present description can also beimplemented using other hydrocarbon recovery processes. Non-limitingexamples of such other hydrocarbon recovery processes include cyclicsteam stimulation (CSS) and Vapor Extraction (VAPEX), among others. Itshould also be understood that the techniques of the present descriptioncan also be implemented with processes utilizing co-injection of steamand solvent.

Still referring to FIG. 1, in some implementations, an oxygen-enrichedmixture 10, fuel 12 and feedwater 14 are fed to a DCSG 16. Theoxygen-enriched mixture 10 can be oxygen-enriched air, or oxygen atdifferent levels of purity. Optionally, high purity oxygen can be used.In some implementations, the oxygen-enriched mixture 10 can be generatedusing an oxygen module 36 which can separate an incoming air stream 38into the oxygen-enriched mixture 10 and oxygen-lean air 40.

Still referring to FIGS. 1, the DCSG 16 can be operated to obtain asteam-based mixture 18 which includes steam and CO₂. Depending on thetype of fuel 12 and oxygen-enriched mixture 10, the steam-based mixture18 can also include various amounts of other gases, as explained above.It is noteworthy that the concentration of CO₂ in an outlet stream of aDCSG which is not subjected to steam-CO₂ separation can be up to 12 wt%, typically between 6 wt % and 12 wt %. In some scenarios, dependingfor example on the properties and geological layout of the reservoir, itcan be desirable to incorporate an additive into the steam-based mixture18 and co-inject the additive into the reservoir along with thesteam-based mixture 18, as will be explained in further detail herein.

Still referring to FIG. 1, the steam-based mixture 18 is injected into ahydrocarbon-bearing reservoir via an injection well 20, and producedfluids 24 are recovered from a production well 22. In someimplementations, the injection well and the production well are locatedon a well pad 23 that is part of the hydrocarbon recovery operation. Theproduced fluids 24 can be separated in separator 26 into a produced gascomponent 28, produced non-gaseous hydrocarbons 30 and produced water32. The produced water 32 can be oily water which can contain some solidmaterials.

In some implementations, the DCSG 16 can operate effectively with lowfeedwater quality, and in some scenarios with feedwater quality that isconsidered unacceptable for steam generation using a once through steamgenerator OTSG or drum boiler. The feedwater 14 can include fresh water,recycled produced water from a steam-assisted hydrocarbon recoveryprocess or a mixture thereof. Recycled produced water can include highlevels of contaminants and impurities (such as volatile organiccompounds, residual hydrocarbons, inorganic compounds and/or suspendedsolids), which can be flared in the DCSG.

In some implementations, all or part of the produced gas 28 can be sentback to a processing facility for separating light hydrocarbons fromunwanted compounds, and/or all or part of the produced gas 28 candirectly be used as part of the fuel 12 for the DCSG 16. In someimplementations, the fuel 12 used for the DCSG can be a mixtureincluding at least a portion of the produced gas 28 and makeup fuel 34.The DCSG 16 can operate using different types of fuel 12, such as benatural gas, syngas, refinery fuel gas, coke, asphaltenes or mixturesthereof. The flexibility in the types of fuel that can be used providesan advantage against escalating natural gas prices or natural gas supplyinterruptions.

In some implementations, the produced non-gaseous hydrocarbons 30 caninclude heavy oil and/or bitumen and are typically further processed orupgraded in a processing facility. At least part of the produced water32 can be recycled back to the DCSG 16 to be used as feedwater. In someimplementations, makeup water 42 can be added to the produced water 32for use as DCSG feedwater. As there is little to no produced gas 28 andproduced water 32 during SAGD startup operations, the feedwater 14 andthe fuel 12 mainly consist of the makeup water 40 and an external sourceof fuel supplied to the DCSG 16, respectively. As production from theSAGD operation begins to ramp up, produced gas 28 and produced water 32can be obtained from the separator 26 and respectively used as part ofthe fuel 12 and feedwater 14, thereby requiring less makeup water 42 andmakeup fuel 34. When the SAGD operation reaches a normal operatingstage, the feedwater 14 can mainly include produced water 32, with avarying amount of makeup water 42 added as required. In someimplementations, very little makeup water 42 is required when the SAGDoperation reaches a ramped-up continuous regime. When the reservoirretains water, as is often the case in SAGD startup, the proportion ofmakeup water 42 to total feedwater 14 is higher. When more water isrecovered from the produced fluids 24, the proportion of makeup water 42to total feedwater 14 is lower. In some scenarios, more water isreleased from the reservoir than is injected. In such cases, no makeupwater is needed and the excess water recovered can be stored for lateruse. In some implementations when SAGD is used, high water productioncan sometimes be observed as a result of prolonged interruptions (e.g.,due to phase separation in the reservoir), such as after unplannedevents (e.g., fires). In some implementations, other operational eventsincluding infill well when in production can lead to different water/oilcuts in produced pad fluids.

Additive Implementations

Still referring to FIG. 1, in some implementations, an additive 44 a, 44b, 44 c (or a plurality of additives) can be provided to the DCSG 16and/or to the steam-based mixture 18 of the DCSG 16. The nature andpurpose of the additive can vary. In some scenarios, the additive can beadded with the goal of improving hydrocarbon recovery. In otherscenarios, the additive can be added with the goal of improving wellintegrity. In some implementations, the temperature and pressureconditions within the main chamber of the DCSG 16 and/or within thesteam-based mixture 18 can condition and/or chemically transform theadditive in order to impart certain properties to the additive. Forexample, an additive in liquid state can be provided to the DCSG 16 andcontacted with hot combustion gas originating from combustion of thefuel 12 and the oxygen-enriched mixture 10, in order to be vaporisedand/or dispersed into the steam-based mixture 18. After contacting thehot combustion gas, the additive can be present in a gaseous stateand/or as a dispersed liquid in the steam-based mixture 18.

It should be understood that the expression “in a liquid state”, as usedherein, refers to the additive being injected into the DCSG as a liquidin pure form, as a mixture with other liquids, or in solution in asolvent such as water. It should also be understood that the expression“in a gaseous state”, as used herein, refers to the additive beingpresent as a gas/vapor in the steam-based mixture. It should also beunderstood that the expression “in a dispersed state”, as used herein,refers to the additive being dispersed into the steam-based mixture ofthe DCSG as gas particles (e.g., a gas mixture) and/or liquid particles(e.g., an aerosol-like phase). In some implementations, the additive isstable under DCSG operating conditions; i.e., the additive can undergophase transition, but most of the additive does not undergo chemicaldegradation or chemical reaction(s), which can change its molecularnature. In some implementations, the additive is vaporizable so that amixture of steam with the additive in gaseous state and/or dispersedstate is obtained as the output stream of the DCSG.

In some implementations, the additive can include ammonia in order toobtain a steam/CO₂/ammonia mixture as the output stream of the DCSG. Insome implementations, the additive can include a volatile amine, inorder to obtain a steam/CO₂/volatile amine mixture as the output streamof the DCSG. In some implementations, the additive can include urea(e.g., a urea solution such as a urea aqueous solution), in order toobtain a steam/CO₂/volatile amine mixture as the output stream of theDCSG. It should be understood that the term “ammonia”, as used herein,refers to either gaseous ammonia or ammonia in solution (in water oranother solvent). For example, the ammonia can be an ammonium hydroxideaqueous solution. Co-injection of steam with ammonia, urea and/orvolatile amine will be discussed in further detail below.

In some implementations, the additive can include at least one of asurfactant, a viscosity reduction agent or a well integrity agent.

It should be understood that the term “surfactant”, as used hereinrefers to amphiphilic compounds (i.e., compounds containing bothhydrophobic groups and hydrophilic groups). The surfactant can benonionic, cationic, anionic or amphoteric. As non-limiting examples, thehydrophobic tail of the surfactant can include a hydrocarbon chain(which can be branched, linear or aromatic), a fluorocarbon chain, asiloxane chain or a polyethylene-like chain (such as polyethylene oxideand/or polypropylene oxide chains). Non-limiting examples of anionicsurfactants have anionic functional groups at their heads, such assulfate, sulfonate, phosphate and carboxylates. Non-limiting examples ofcationic surfactants have cationic functional groups at their heads,such as primary, secondary, tertiary ammonium salts (which are pHdependent), quaternary ammonium salts (which are pH independent).Amphoteric surfactants have both cationic and anionic centers at theirhead (or at two opposed heads). Non-limiting examples of nonionicsurfactants include fatty alcohols, polyethylene glycol alkyl ethers,polypropylene glucol alkyl ethers, glucoside alkyl ethers, glycerolalkyl esters, block copolymers of polyethylene glycol and polypropyleneglycol, among others.

It should be understood that the term “viscosity reducing agent”, asused herein, refers to an agent that, when injected into the reservoiralong with the steam-based mixture, reduces the viscosity of theproduced fluids compared to the viscosity of produced fluids obtainedwhen no viscosity reducing agent is used. In some scenarios, theviscosity reducing agent can reduce the viscosity of the produced fluidsby at least 10%. Non-limiting example of viscosity reducing agents mayinclude alkane-based formulations such as paraffinic oil, diethylsebacate, diethylene glycol monoethyl ether, ethyl alcohol, ethyl oleate(EO), isopropyl alcohol (IPA), isopropyl myristate, linoleic acid,propionic acid, triethyl citrate, propylene glycol, ethanol, propanol,isopropanol, polyethylene glycol, polyperfluoroethers, fluorocarbon(halothane, methoxyflurane, enflurane, isoflurane, sevoflurane anddesflurane, etc.), fluorinated ketone, perfluorodecalin,perfluoroacrylate, perfluoromethacrylate, benzyl alcohol, laurylalcohol, perfluorodecalin, N-Methyl-2-pyrrolidone, glycofurol,polyethylene glygol (PEG) , alkyl ketone, lower alkyl ester of citricacid, benzyl benzoate, methyl benzoate, ethyl benzoate, n-propylbenzoate, isopropyl benzoate, butyl benzoate, isobutyl benzoate,sec-butyl benzoate, tert-butyl benzoate, and isoamyl benzoate, ormixtures thereof.

It should be understood that the term “well integrity agents”, as usedherein, refers to compounds that can promote structural integrity of thetubing/annulus of an injection or production well, downhole tools (e.g.,ESP, instrumentation) and/or structural integrity of the reservoir, ifdamaged. Non-limiting examples of well integrity agents includeanticorrosive agents, antifouling agents, scale inhibitors and thermallystable cements that can block areas of a well that are permeable tosteam.

As shown in FIG. 1, in some implementations, additive 44 a can be addedas part of the feedstream of the DCSG 16, along with the feedwater 14.For example, the additive 44 a and the feedwater 14 can be mixed priorto being provided to the DCSG 16. In some implementations, the feedwater14 can be provided as a feedwater stream and additive 44 b can beprovided to the DCSG 16 as a separate additive stream. In someimplementations, additive 44 c can be provided to the output stream 18of the DCSG 16. In some implementations, the feedwater 14 can becontacted with the hot combustion gas for a longer time period than theadditive 44 b. In other words, the additive 44 b can be provided to theDCSG 16 at an inlet which is distant from the feedwater inlet, so thatthe additive 44 b is not subjected to DCSG temperature and pressureconditions for a time period as long as the feedwater 14.

Ammonia/Volatile Amine Implementations

Still referring to FIG. 1, in some implementations, the additive caninclude at least one of ammonia, urea and a volatile amine. In suchcase, a steam/CO₂/ammonia mixture, a steam/CO₂/volatile amine,steam/CO₂/urea, a steam/CO₂/ammonia/volatile amine or asteam/CO₂/urea/ammonia/volatile amine mixture is obtained as thesteam-based mixture 18. In some implementations, ammonia can begenerated using the DCSG by reaction of urea and/or of the ammoniumhydroxide solution.

It should be understood that the term “volatile amine”, as used herein,refers to a single amine or a mixture of amines. In someimplementations, such volatile amine can have a boiling point atatmospheric pressure of 150° C. or less, and/or a pKa of 5.0 or more.Non-limiting examples of volatile amine include C₃-C₈ amines, such asmethyl amine, dimethyl amine, trimethyl amine, diethyl amine, ethylamine, isopropyl amine, n-propyl amine, diethyl amine, 1,1-dimethylhydrazine, isobutyl amine, n-butyl amine, pyrrolidone, triethylamine,methyl hydrazine, piperidine, dipropylamine, hydrazine, pyridine,ethylenediamine, 3-methoxypropylamine, N, N-diethylhydroxylamine,morpholine, pyrrole, cyclohexylamine or a mixture thereof.

In some embodiments, the ammonia and/or the volatile amine can beprovided to the DCSG 16 with the feedwater 14. The ammonia and/or thevolatile amine can be mixed with the feedwater 14 prior to beinginjected into the DCSG 16, or injected into the DCSG 16 separately. Insome scenarios, the ammonia can be injected into the DCSG 16 as anaqueous ammonium hydroxide solution. In some scenarios, the volatileamine can be injected into the DCSG 16 as an aqueous solution. In whatfollows, the term NH₂-containing compound is used to refer to ammonia orvolatile amine. The feedwater 14 and the NH₂-containing compoundfeedstream can be contacted with hot combustion gases of the DCSG 16such that a steam-based mixture 18 including steam, CO₂ and theNH₂-containing compound is obtained. In some scenarios, theNH₂-containing compound is in a gaseous state and/or in a dispersedstate within the steam-based mixture 18.

Using the DCSG 16 to incorporate the NH₂-containing compound into thesteam-based mixture 18 can reduce the operating costs, for example, ifno separate heating means are needed in order to volatilize theNH₂-containing compound. Using the DCSG 16 to incorporate theNH₂-containing compound into the steam-based mixture 18 can increasesafety, as fewer personnel can be required to handle hazardous material.Using the DCSG 16 to incorporate the NH₂-containing compound into thesteam-based mixture 18 can also reduce the need to process theNH₂-containing compound at a processing facility and the need forpipelining the heated NH₂-containing compound from the processingfacility to the injection well. The use of an NH₂-containing compoundcan lower steam requirements, as the hydrocarbons in the reservoir canbe more easily mobilized.

In some implementations, the concentration of the NH₂-containingcompound in the steam-based mixture can be between about 0.1 wt % andabout 30 wt %, or between about 0.5 wt % and about 10 wt %, or betweenabout 1 wt % and about 5 wt %. In some implementations, the additiveincludes ammonium hydroxide solution (e.g., 500-2000 ppm of ammonia inwater) at a concentration in the steam-based mixture between about 20and 30 wt %.

In some implementations, the steam-based mixture can have the followingcomposition, which is given as a non-limiting example:

Steam: about 75 wt % to 99.9 wt %

Ammonia: about 0.1 wt % to 30 wt %; and

CO₂: about 2 wt % to 12 wt %.

In some implementations, the NH₂-containing compound can be provideddirectly to the combustion mixture of the DCSG. As the temperature andpressure of the output stream of a DCSG are typically high, providingthe NH2-containing compound to the output stream of the DCSG can heat upthe NH₂-containing compound to a temperature which is sufficient so thatthe NH₂-containing compound is vaporized and/or dispersed into thecombustion mixture.

Steam-CO₂ Separation Implementations

In some scenarios, depending for example on the properties andgeological layout of the reservoir, it can be desirable to lower theconcentration of CO₂ in the injection mixture to be injected into thereservoir. For example, the concentration of CO₂ in the injectionmixture can be desired to be at most about 4 wt % or at most about 2 wt%.

Now referring to FIG. 2A, a steam-CO₂ separation unit 46 can be provideddownstream of the DCSG 16. All or part of the CO₂ can be separated fromthe combustion mixture 18 to obtain a CO₂-depleted steam stream 48 and aCO₂-rich stream 50. The CO₂-depleted steam stream 48 can be injectedinto the reservoir through the injection well 20. In someimplementations, the additive 44 a, 44 b, 44 c can be added similarly asdescribed above. In some implementations, the additive 44 d can be addedto the CO₂-depleted steam stream 48, downstream of the steam-CO₂separation.

Now referring to FIG. 2B, in some implementations, the combustionmixture 18 can be split into at least two separate portions 48A and 48B.The first portion 48A can be supplied to a steam-CO₂ separation unit 46.All or part of the CO₂ can be separated from the first portion 48A inthe steam-CO₂ separation unit 46 in order to obtain a CO₂-depleted steamstream 48 and a CO₂-rich stream 50. In some implementations, thesteam-CO₂ separation unit 46 can include a membrane separation unitincluding at least one separation membrane suitable for separating atleast part of the steam and at least part of the CO₂ from a DCSGcombustion mixture. Optionally, when a steam-CO₂ membrane separationunit 46 is used, sweep gas 52 can be provided to the separation unit 46for driving the separation. The sweep gas 52 can be composed of acombustible mixture which is suitable to (i) drive the separation of thesteam and CO₂ from the combustion mixture 18 and (ii) be used as fuelfor a DCSG, for example when the CO₂-depleted steam stream 48 isrecycled back into the DCSG 16. When the sweep gas 52 is used as part ofthe fuel, the CO₂-depleted steam stream 48 mainly includes steam andsweep gas 52, and can also include a residual amount of CO₂. Forexample, the sweep gas 52 can include natural gas or other combustiblefuel gases such as lower hydrocarbons (e.g., methane, ethane, propaneand/or butane), a synthetic fuel gas such as syngas, or a refinery fuelgas. For example, the concentration of steam in the CO₂-depleted steamstream 48 can be up to 90 wt %, and the concentration of sweep gas inthe CO₂-depleted steam stream 48 can be up to 10 wt %. The concentrationof residual CO₂ in the CO₂-depleted steam stream 48 can be up to 1 wt %.It is understood that the composition of the CO₂-depleted steam streamcan vary when the additive is added at 44 a, 44 b and/or 44 c, and thatin such case, the nature and/or amount of sweep gas which is needed forthe separation can also vary.

In some implementations, the CO₂-rich stream 50 is mainly composed ofCO₂. For example, the concentration of CO₂ in the CO₂-rich stream 50 canbe up to 90 wt %, and the concentration of steam in the CO₂-rich stream50 can be up to 10 wt %. It should be understood that the concentrationof CO₂ in the CO₂-rich stream depends on the type of separation unit 46used and can change depending on various operating factors, such as theconcentration of CO₂ in the combustion mixture 18, the temperature andpressure at which the separation is effected and the nature andconcentration of sweep gas 52 used.

Still referring to FIG. 2B, in some implementations, the CO₂-depletedsteam stream 48 is recycled back to the DCSG 16. As the CO₂-depletedsteam stream 48 includes mainly steam and sweep gas, the CO₂-depletedsteam stream 48 can be suitable for use as part of the feedwater 14 andpart of the fuel 12 for the DCSG 16. As the CO₂-depleted steam stream 48typically only includes a residual amount of CO₂, recycling theCO₂-depleted steam stream 48 back to the DCSG 16 can facilitategradually lowering the concentration of CO₂ in the combustion mixture 18until steady-state or quasi steady-state concentrations are reached. Thecombustion mixture 18 is split (e.g., using a splitter 54) into thefirst portion 48A which is introduced into the steam-CO₂ separation unit46 and the second portion 48B which can be used for the desiredapplication, such as injection into a hydrocarbon-bearing reservoir. Theamount of the combustion mixture 18 supplied to the steam-CO₂ separationunit 46 (i.e., the first portion 48A) depends on the desiredconcentration of CO₂ in the combustion mixture 18 when the steady-stateregime or quasi steady state regime is reached.

Still referring to FIG. 2B, in some implementations, the additive 44 a,44 b, 44 c can be added similarly as described above. In someimplementations, the additive 44 d can be added into the second portion48B of the combustion mixture, after separation by the splitter 54, andbefore the second portion 48B is injected into the reservoir. In someimplementations, the additive 44 e can be added to the CO₂-depletedsteam stream 48 prior to the CO₂-depleted steam stream 48 being recycledback to the DCSG 16. In some implementations, the additive 44 f can beadded to the sweep gas stream 52, for example in order to help drive theseparation of the steam and the CO₂. It is understood that not alladditives can be added at any injection point. For example, an additivewhich is not stable under DCSG operating conditions is not to be addedat 44 a. Similarly, an additive which cannot act as a sweep gas is notto be added at 44 f. In some implementations, the produced fluid 24 caninclude a portion of the additive injected into the reservoir. In someimplementations, the separator 26 can separate the additive from theproduced fluid 24 and the recovered additive can be re-used at any oneof the injection points discussed herein.

Remote Injection Implementations

Referring to FIG. 3, a SAGD operation is shown, which includes severalremote hydrocarbon recovery facilities 54 located at a remote distancefrom a processing facility 56 supporting the SAGD operation. Each of theremote hydrocarbon recovery facilities can include at least one steamgenerator 16, at least one well pad 23 for supporting the SAGD wells andassociated equipment and piping, SAGD well pairs 21 extending from thewell pad 23 into the reservoir, and at least one separator 26.

It should be understood that “located at a distance” means that thehydrocarbon recovery facilities 54 are not located in proximity to theprocessing facility 56. It is typical for the processing facility 56 tobe located several kilometers from the remote hydrocarbon recoveryfacilities 54 being supported. It should also be understood that a“remote hydrocarbon recovery facility” is a facility that is located ina geographical area and includes at least one well pad 23 withcorresponding SAGD well pairs 21, at least one steam generator 16 and atleast one separator 26. The steam generator 16 and the separator 26 areinstalled in proximity to the at least one well pad 23. In this context,it should be understood that “in proximity” means that the steamgenerator 16 and separator 26 are located on the well pads 23 forsupplying steam to the wells of the same well pad and treatingproduction fluids retrieved from the same well pad; on an adjacent wellpad 23 of the same hydrocarbon recovery facility 54; or in the generalarea as the well pads 23 of the given hydrocarbon recovery facility 54and remote from the processing facility 56. Some examples of “inproximity” could mean that the steam generator 16 and separator 26 arelocated within about 200 meters, about 100 meters, about 50 meters, oreven about 20 meters of the well pads 23.

Still referring to FIG. 3, each remote hydrocarbon recovery facility 54can be provided with at least one water supply tank 58 and at least oneadditive supply tank 60. In some scenarios, a water supply tank 58and/or an additive supply tank 60 provided at the remote hydrocarbonrecovery facilities can remove or reduce the need for conveying waterand/or additive from the distant processing facility 56, and cantherefore reduce costs associated with pipelining or transporting thewater and/or the additive. In some implementations, an additive tank canbe provided at the remote hydrocarbon recovery facility 54 to reduce thetransporting and/or handling of the additive over long distances.

Disposal of Volatile Organic Compounds (VOCs) Implementations

In some implementations, the DCSG can include a waste inlet forreceiving a waste stream to be flared (i.e., destroyed). The wastestream can for example include volatile organic components (VOCs) whichcan originate from any stream of the hydrocarbon recovery operationwhich contains organic components. For example, waste streamsoriginating from the separation of the produced fluids 24 into theproduced gas 28 and/or non-gaseous hydrocarbon component 30 can beprovided to the DCSG 16 and be injected along with the feedwater 14 orin conjunction with the feedwater 14 to be flared under DCSG operatingconditions. In some implementations, the waste streams to be flared canoriginate from third parties.

Additives with Carrier Gas Implementations

In some implementations, the additive to be provided to the DCSG 16 canbe carried by a heat carrier gas. The heat carrier gas can providethermal stability to the additive during operation of the DCSG. This canbe useful in scenarios where the additive is not stable under DCSGoperating conditions, in order to improve the stability of the additive.In some scenarios, the heat carrier gas can absorb at least part of theheat instead of the additive, thereby allowing a higher proportion ofthe additive to exit the DCSG without being degraded and while retainingthe properties of the additive. Non-limiting examples of carrier gasesinclude non-condensable gases such as CO₂ and nitrogen, steam at a lowertemperature than outgoing steam.

System Implementations

In some implementations, there is provided a system for recoveringhydrocarbons from a reservoir. The system includes a DCSG 16 forgenerating a combustion mixture 18. The DCSG 16 has an oxygen inlet, afuel inlet and a feedwater inlet respectively connected to an oxygensupply line, a fuel supply line and a feedwater supply line. The DCSGcan also have an additive inlet connected to an additive supply. In someimplementations, the additive supply can be connected to the feedwatersupply line, for providing the additive through the feedwater inlet. TheDCSG 16 is provided with a combustion mixture outlet, and is in fluidcommunication with the injection well.

The production well 22 can allow for the recovery of the produced fluids24 from the reservoir. The system can also include a separator 26 influid communication with the production well 22 to receive the producedfluids 24. The separator 26 can produce produced gas 28, producednon-gaseous hydrocarbons 30 and produced water 32. The separator 26 canbe in fluid communication with the DCSG 16, for example to feed at leasta portion of the produced water 32 as feedwater to the DCSG 16, or tofeed at least a portion of the produced gas 28 as fuel to the DCSG 16.

In some implementations, a steam-CO₂ separation unit can be provideddownstream of the DCSG and upstream of the injection well. The steam-CO₂separation unit 46 can be provided with a combustion mixture inlet, asweep gas inlet, a CO₂-rich stream outlet and a CO₂-depleted steamstream outlet. In some implementations, the combustion mixture outlet ofthe DCSG 16 can be connected to the steam-CO₂ separation unit 46 througha splitter 54, and the CO₂-depleted steam stream outlet of theseparation unit 46 can be connected to the fuel inlet (or anotherdedicated CO₂-depleted steam stream inlet) of the DCSG 16. The splitter54 separates the combustion mixture 18 into first and second portions48A, 48B. The system also includes a well pad 23 supporting a well pair,the well pair including an injection well 20 and a SAGD production well22.

Well-known methods, procedures and components have not been described indetail so as not to obscure the above description. The steps oroperations in the flow charts and diagrams described herein are just forexample and are not to be considered limiting. There may be variationsto these steps or operations without departing from the principlesdiscussed herein. For instance, the steps may be performed in adiffering order, or steps may be added, deleted, or modified.

Although the above principles have been described with reference tocertain specific examples and implementations, various modificationsthereof will be apparent to those skilled in the art as outlined in theappended claims.

1. A process for in situ thermal recovery of hydrocarbons from areservoir, comprising: providing an oxygen-enriched mixture, fuel,feedwater and an additive comprising at least one of ammonia, urea or avolatile amine to a direct-contact steam generator (DCSG); operating theDCSG, comprising contacting the feedwater and the additive with hotcombustion gas to obtain a steam-based mixture comprising steam, CO₂ andthe additive; injecting the steam-based mixture or a stream derived fromthe steam-based mixture into the reservoir to mobilize the hydrocarbonstherein; and producing a produced fluid comprising the hydrocarbons. 2.The process of claim 1, wherein the additive comprises ammonia.
 3. Theprocess of claim 2, wherein the ammonia is provided as an ammoniumhydroxide solution.
 4. The process of claim 1, wherein the concentrationof the additive in the steam-based mixture is between about 0.1 wt % andabout 30 wt %.
 5. The process of claim 1, wherein the steam-basedmixture comprises the additive in a gaseous and/or vapor state.
 6. Theprocess of claim 1, wherein the additive further comprises at least oneof a viscosity reduction agent or a well integrity agent.
 7. The processof claim 1, wherein the feedwater and the additive are provided as asingle feed stream to the DCSG.
 8. The process of claim 1, wherein thefeedwater is provided as a feedwater stream and the additive is providedas a separate additive stream, to the DCSG.
 9. The process of claim 1,wherein the feedwater stream is contacted with the hot combustion gasfor a longer time period than the additive stream.
 10. A system forrecovering hydrocarbons from a reservoir, comprising: a DCSG forgenerating a steam-based mixture, the DCSG comprising: an oxygen inletfor receiving an oxygen-enriched mixture; a fuel inlet for receivingfuel; and at least one inlet for receiving feedwater and an additivecomprising at least one of ammonia, urea or a volatile amine, thesteam-based mixture comprising steam, CO₂ and the additive; an injectionwell in fluid communication with the DCSG to receive the steam-basedmixture or a stream derived from the steam-based mixture; a productionwell for recovering produced fluids from the reservoir; and ahydrocarbon separating unit in fluid communication with the productionwell to receive the produced fluids and separate the hydrocarbons fromthe produced fluids.
 11. The system of claim 10, wherein the additivecomprises ammonia.
 12. The system of claim 11, wherein the ammonia isprovided as an ammonium hydroxide solution.
 13. The process of claim 11,wherein the steam-based mixture comprises the additive in a gaseousstate.
 14. The system of claim 10, wherein the additive furthercomprises at least one of a viscosity reduction agent or a wellintegrity agent.
 15. The system of claim 10, wherein the concentrationof the additive in the steam-based mixture is between about 0.1 wt % andabout 30 wt %.
 16. The system of claim 10, wherein the at least oneinlet for receiving the feedwater and the additive is a single inlet,such that the feedwater and the additive are provided as a single feedstream to the DCSG.
 17. The system claim 10, wherein the at least oneinlet for receiving the feedwater and the additive comprises a feedwaterinlet and a separate additive inlet, such that the feedwater is providedas a feedwater stream and the additive is provided as a separateadditive stream, to the DCSG.
 18. The system of claim 10, wherein theinjection well and the production well are formed within two separatewell bores.
 19. The system of claim 10, wherein the injection well andthe production well are formed within a single well bore.
 20. A processfor in situ thermal recovery of hydrocarbons from a reservoir,comprising: providing an oxygen-enriched mixture, fuel, feedwater and anadditive in liquid state to a DCSG; operating the DCSG, comprisingcontacting the feedwater and the additive with hot combustion gas toobtain a steam-based mixture comprising steam, CO₂ and the additive in agaseous state and/or a dispersed state; injecting the steam-basedmixture or a stream derived from the steam-based mixture into thereservoir to mobilize the hydrocarbons therein; and producing a producedfluid comprising the hydrocarbons.